Touchstone Announces 2020 Year-End Reserves and Provides Operational Update

CALGARY, AB, March 5, 2021 /CNW/ - Touchstone Exploration Inc. ("Touchstone", "we", "our", "us" or the "Company") (TSX: TXP), (LSE: TXP)  announces a summary of its 2020 year-end reserves and provides an operational update.

Our independent reserves evaluation was prepared by GLJ Ltd. ("GLJ") with an effective date of December 31, 2020 (the "Reserves Report"). Highlights of our total proved ("1P"), total proved plus probable ("2P") and total proved plus probable plus possible ("3P") reserves from the Reserves Report are provided below. All finding and development ("F&D") costs below include changes in future development capital ("FDC"). Unless otherwise stated, all financial amounts referenced herein are stated in United States dollars. Financial information contained herein is based on the Company's unaudited results for the year ended December 31, 2020 and is subject to change. Readers are further cautioned to read the applicable advisories contained herein.

2020 Year-end Reserves Report Highlights

• Increased 3P net reserves by 236% to 100,150 Mboe, increased 2P net reserves by 194% to 64,947 Mboe and increased 1P net reserves by 189% to 34,238 Mboe from the prior year.
• In comparison to 2019, 10% discounted net present value of future net revenues ("NPV10") on a before tax 3P basis increased by 90% to $1,002.8 million and after tax 3P NPV10 increased by 108% to $419.4 million.
• Achieved a before tax 2P NPV10 of $683.1 million, representing an increase of 72% from $397.9 million reported in 2019 and realized an annual after tax 2P NPV10 increase of 88% to $289.2 million.
• Realized before tax 1P NPV10 of $362.9 million, representing an increase of $160.7 million or 79% from the prior year and increased after tax 1P NPV10 by 95% from year-end 2019 to $163.0 million.
• Realized 1P F&D costs of $1.26 per boe, resulting in a recycle ratio 11.3 times using our unaudited annual estimated 2020 operating netback of $14.29 per boe. Touchstone's low F&D costs are primarily attributed to our meaningful 2020 reserves growth from our Cascadura-1ST1 well discovery.
• Recognized 2P F&D costs of $0.71 per boe, resulting in a 2P recycle ratio of 20.3 times, demonstrating Touchstone's capital efficient operations in the Ortoire block.
• FDC associated with only a portion of our internally identified drilling location inventory and low-risk recompletion projects totaled $55.9 million for 1P reserves and $83.9 million for both 2P and 3P reserves.
• The Cascadura assessment area was assigned gross working interest 1P reserves of 23,622 Mboe and gross working interest 2P reserves of 45,030 Mboe with an estimated before tax 2P NPV10 of $411.8 million.
• The Reserves Report excluded any potential reserves from the Company's Chinook-1 and Cascadura Deep-1 wells drilled in the fourth quarter of 2020.

Paul Baay, President and Chief Executive Officer, commented:

"Our year-end 2020 reserves evaluation provides further independent confirmation of the significant opportunities that the Company has in place from our Trinidad assets. Our 1P reserves are now significantly higher than our 3P reserves at the same time last year, providing greater operational and financial certainty for investors, and exclude any potential reserves from the recently drilled Chinook-1 well or Cascadura Deep-1 wells. We have a lot to be excited about as we focus on converting our world class reserves to production during 2021 as well as expanding opportunities through additional drilling at Ortoire."

Operational Highlights

• Tested two identified pay zones in the Chinook-1 well, with both zones encountering potential upside in the form of light sweet crude oil. One pay zone is currently being configured for an extended production test.
• Equipment has arrived in Trinidad to enable testing of the main gas bearing zones in the Cascadura Deep-1 well, where significant hydrocarbon accumulations were reported in December based on drilling and wireline logging data.
• Testing of the potential gas bearing sands in the Chinook-1 well will commence following the extended crude oil test.
• We continue to target the second quarter of 2021 for initial Ortoire gas commercialization, with final regulatory approvals for the tie-in of our Coho-1 well received and construction underway.
• Working with the National Gas Company of Trinidad and Tobago to commence regulatory applications to tie-in Cascadura and any potential Chinook production volumes, with the objective of achieving initial production prior to the end of 2021.
• The primary access road to the Royston-1 well location has been cleared, and we have commenced road resurfacing and lease building operations.
• Initiated line clearing for the 21-kilometre 2D seismic program in the Royston area.
• Expected to enter into a minimum three-year drilling services contract from a Canadian based private company to supply an ultra-heavy telescopic drilling rig to Trinidad in late 2021, which will enable us access to three drilling rigs in Trinidad capable of drilling to depths of 10,000 feet or more.

Operational Update

Well Testing

Touchstone has yet to test the targeted gas bearing zones in the Chinook-1 and Cascadura Deep-1 exploration wells due to unavoidable delays associated with third-party equipment including the natural gas testing unit. However, we are pleased to report that all required equipment has now been cleared through the various levels of government organizations in Trinidad and is expected to be on location within the next ten days.

Touchstone has tested two low resistivity zones in the Chinook-1 well. The first test interval was in the lower sub-thrust sheet, which was a previously unknown thrust-sheet where we identified 68 net feet of potential pay based on wireline logging data. During this test, the well recovered trace amounts of 41 degrees API sweet oil along with significant high pressure and high temperature water, which was indicative of encountering a fracture at the base of the formation. With the high volume of water, the zone is considered uneconomic; however, indications of light oil prove the concept of hydrocarbons in the sub-thrust sheet. Based on 3D seismic data, future development locations are anticipated to be positioned structurally up-dip by as much as 1,000 feet from the Chinook-1 well to evaluate the sub-thrust sheet in an optimal structural position. The Company has permanently abandoned this lowermost zone and completed a second zone in the Herrera formation which encountered 35 degrees API sweet oil and is currently being configured for an extended oil production test. We anticipate conducting the first natural gas test at the Cascadura Deep-1 well while the Chinook-1 well is on the extended oil production test.

James Shipka, Chief Operating Officer, commenting on the Chinook-1 well tests, said:

"This is an encouraging start to the production testing program as it confirms the presence of hydrocarbons in the sub-thrust sheet and will allow for further up-dip drilling targets based on available 3D seismic data. The sub-thrust sheet was not one of the original Chinook-1 well targets, so the confirmation of hydrocarbons in the deep section is very positive. Although the lower zone was considered uneconomic given the high water cuts, the reservoir displayed potential as fluid flowed to surface at over 2,200 bbls/d. Future targets structurally up-dip from Chinook-1 hold tremendous potential.

The second production test is also very exciting and could result in numerous development locations. The presence of oil in the intermediate section reaffirms that the hydrocarbon system in the Herrera is extensive and variable. Our extended production test will determine if this zone is commercial in Chinook-1 before we move up in the wellbore to our next test which we anticipate being a natural gas zone immediately above the oil. It is unfortunate that due to third-party issues beyond our control we have had to wait on the gas test equipment; nevertheless, valuable data has been collected in the interim period.

The multi-target project at Ortoire is still in the early stages. The oil discovery at Chinook-1 adds another layer of opportunity that we have not previously forecasted. For reference, the offsetting Barrackpore oil pool has over 60 wells that have produced approximately 18.7 million barrels, averaging 300,000 barrels per well with oil ranging from 27 to 30 degrees API."

Coho-1 Tie-in

On January 22, 2021, the Company received approval to proceed with the construction of the Coho-1 tie-in project. Subsequent to the required initial notification period, construction operations have commenced. Touchtone is targeting initial gas production from Coho-1 in the second quarter of 2021. In conjunction with the project, we have also been working with the Natural Gas Company of Trinidad and Tobago to survey and commence regulatory applications to tie-in Cascadura and any potential Chinook production volumes, with a goal to achieve initial production prior to the end of 2021. The Company is concurrently applying for two additional surface locations at both Cascadura and Chinook which will allow for up to 16 development locations.

Royston Drilling Preparations

Touchstone is pleased to report that we have cleared the primary access road to the Royston-1 drilling location and are currently surfacing the road and performing lease preparations. The Royston well will be drilled using Well Services Rig #60 targeting a total depth of approximately 11,500 feet. The drilling rig is scheduled to move onto location early in the second quarter of 2021. 

Drilling Rig Contract

Given our exploration success, the Company expects to execute a contract with a Canadian based private company to provide state of the art drilling equipment commencing in late 2021. The contractor will deploy a North American based drilling rig equipped for us to evaluate the deep targets at Royston, Cascadura and Chinook along with drilling on our legacy crude oil development properties. Pursuant to the current terms of the drilling contract, Touchstone must utilize the rig for a minimum of 120 days per year over an initial three-year term and is obligated to pay for rig mobilization costs, which are currently estimated to be approximately $1 million. This arrangement, in combination with our current drilling services provider, will give the Company access to three drilling rigs capable of drilling to depths of 10,000 feet or more on the Ortoire block as well as the Company's legacy oil development properties.

Seismic Program

Touchstone has initiated surveying and line clearing for our 21-kilometre 2D seismic program. The seismic information will be used for further delineation of the structure to be drilled at Royston and adjacent prospects in the Mid Miocene Herrera formation and is expected to optimize future drilling into the previously identified Cretaceous exploration target. The program is scheduled to be completed prior to July 2021. 

2020 Year-end Reserves Report Summary

Touchstone's 2020 capital program focused on exploration activities on our Ortoire property, where we drilled two gross (1.6 net) exploration wells. Similar to 2019, we conducted minimal capital development activity on our development properties, mainly performing wellbore recompletions and workover operations to arrest production declines. The Reserves Report includes those reserves associated with our legacy development properties and our Coho natural gas discovery in 2019, as well as new reserves associated with our Cascadura discovery in 2020. The Reserves Report does not include any reserves associated with our Chinook-1 and Cascadura Deep-1 wells drilled in 2020, as production testing operations were not completed prior to the effective date of the Reserves Report. 

Touchstone's year-end crude oil and natural gas reserves in Trinidad were evaluated by independent reserves evaluator, GLJ, in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional reserves information as required under NI 51-101 will be included in the Company's Annual Information Form, which will be filed on SEDAR on or before March 31, 2021. The reserve estimates set forth below are based upon GLJ's Reserves Report dated March 4, 2021 with an effective date of December 31, 2020. All values in this news release are based on GLJ's forecast prices and estimates of future operating and capital costs as at December 31, 2020. In certain tables set forth below, the columns may not add due to rounding.

Summary of Company Gross Oil and Gas Reserves as of December 31, 2020 by Product Type^(1),(2)

Reserves Category	Light and Medium Oil (Mbbl)	Heavy Oil (Mbbl)	Conventional Natural Gas (MMcf)	Natural Gas Liquids (Mbbl)	Total Oil Equivalent (Mboe)
Proved
Developed Producing	3,470	175	-	-	3,644
Developed Non-Producing	1,717	367	48,708	1,061	11,264
Undeveloped	3,703	-	81,313	2,074	19,329
Total Proved	8,890	542	130,021	3,136	34,238
Probable	6,562	469	125,022	2,842	30,709
Total Proved plus Probable	15,452	1,010	255,043	5,977	64,947
Possible	4,873	362	157,386	3,738	35,203
Total Proved plus Probable plus Possible	20,325	1,372	412,429	9,715	100,150

Notes:
(1)	Gross reserves are the Company's working interest share of the remaining reserves before deduction of any royalties.
(2)	See "Advisories: Reserves Advisory".

Summary of Net Present Values of Future Net Revenues Before Tax as of December 31, 2020 ^(1),(2)

Reserves Category	Net Present Values of Future Net Revenues Before Income Taxes Discounted at (% per year) ($000's)
	0%	5%	10%	15%	20%
Proved
Developed Producing	61,934	45,680	37,399	32,106	28,344
Developed Non-Producing	207,971	162,378	133,400	112,822	97,384
Undeveloped	351,317	255,396	192,092	148,557	117,550
Total Proved	621,222	463,454	362,891	293,485	243,278
Probable	646,336	439,959	320,192	243,712	191,811
Total Proved plus Probable	1,267,557	903,413	683,084	537,197	435,089
Possible	737,859	463,396	319,751	234,400	179,349
Total Proved plus Probable plus Possible	2,005,416	1,366,809	1,002,835	771,597	614,438

Notes:
(1)	Based on GLJ's December 31, 2020 escalated price forecast. See "Summary of Pricing and Inflation Rate Assumptions".
(2)	See "Advisories: Reserves Advisory".

Summary of Net Present Values of Future Net Revenues After Tax as of December 31, 2020 ^(1),(2),(3)

Reserves Category	Net Present Values of Future Net Revenues After Income Taxes Discounted at (% per year) ($000's)
	0%	5%	10%	15%	20%
Proved
Developed Producing	35,991	29,848	26,081	23,358	21,259
Developed Non-Producing	90,946	74,294	62,920	54,527	48,055
Undeveloped	140,503	100,506	74,021	55,827	42,929
Total Proved	267,440	204,648	163,022	133,712	112,242
Probable	254,214	173,852	126,150	95,476	74,642
Total Proved plus Probable	521,655	378,501	289,172	229,188	186,884
Possible	294,079	187,684	130,262	95,795	73,487
Total Proved plus Probable plus Possible	815,734	566,185	419,434	324,983	260,371

Notes:
(1)	Based on GLJ's December 31, 2020 escalated price forecast. See "Summary of Pricing and Inflation Rate Assumptions".
(2)	See "Advisories: Reserves Advisory".
(3)	Income taxes include all resource income, appropriate income tax calculations per current Republic of Trinidad and Tobago tax regulations and estimated unaudited December 31, 2020 consolidated tax pools and non-capital losses. See "Advisories: Unaudited Financial Information".

Reconciliation of Changes in Gross Reserves by Product Type^(1),(2)

Reserves Category and Factors	Light and Medium Crude Oil (Mbbl)	Heavy Crude Oil (Mbbl)	Conventional Natural Gas (MMcf)	Natural Gas Liquids (Mbbl)	Total Oil Equivalent (Mboe)
Total Proved
December 31, 2019^(3)	9,590	1,103	6,888	-	11,840
Exploration discoveries	-	-	122,916	3,136	23,622
Technical revisions	(196)	(516)	218	-	(675)
Economic factors	(33)	(12)	-	-	(45)
Production	(471)	(33)	-	-	(504)
December 31, 2020	8,890	542	130,021	3,136	34,238
Total Proved plus Probable
December 31, 2019^(3)	16,906	1,801	20,091	-	22,056
Exploration discoveries	-	-	234,318	5,977	45,030
Technical revisions	(934)	(743)	634	-	(1,571)
Economic factors	(50)	(15)	-	-	(65)
Production	(471)	(33)	-	-	(504)
December 31, 2020	15,452	1,010	255,043	5,977	64,947

Notes:
(1)	Gross reserves are the Company's working interest share of the remaining reserves before deduction of any royalties.
(2)	See "Advisories: Reserves Advisory".
(3)	Prior year reserve estimates per GLJ's independent reserves evaluation dated March 4, 2020 with an effective date of December 31, 2019.

In comparison to December 31, 2019 on a 2P reserve basis, light and medium crude oil reserves decreased 984 Mbbl from technical revisions and economic factors in 2020. Approximately 597 Mbbl of this change reflected decreased well performance from the Company's Coora, WD-8 and WD-4 blocks. In addition, the removal of future development locations on the Company's Barrackpore and San Francique properties decreased 2P reserves by approximately 387 Mbbl.

Heavy crude oil was attributed combined downward technical revisions and economic factors of 758 Mbbl as of December 31, 2020, primarily reflecting a decrease in future development locations on Touchstone's Fyzabad and New Dome properties based on decreased future planned activity and expenditures.

Upward technical revisions of approximately 106 Mboe were reflective of reduced surface loss estimates related to the Coho natural gas discovery in 2019. The Company's successful Cascadura-1ST1 well drilled and tested on our Ortoire property led to a 45,030 Mboe increase in conventional natural gas and natural gas liquids 2P reserves in 2020.

Future Development Costs

The following table provides information regarding the future development costs deducted in the estimation of the Company's future net revenue using forecast prices and costs as included in the Reserves Report. 

Year	Proved Reserves ($000's)	Proved plus Probable Reserves ($000's)	Proved plus Probable plus Possible Reserves ($000's)
2021	9,530	11,360	11,360
2022	16,236	23,397	23,397
2023	12,584	16,787	16,787
2024	8,906	17,759	17,759
2025	8,666	14,625	14,625
Thereafter	-	-	-
Total undiscounted	55,920	83,927	83,927
Total discounted at 10% per year	45,098	66,584	66,584

The following table sets forth the changes in undiscounted future development costs included in the Reserves Report against such costs included in the December 31, 2019 reserves report.

($000's unless otherwise stated)	Proved Reserves	Proved plus Probable Reserves	Proved plus Probable plus Possible Reserves
Increase in forecasted capital costs	1,645	1,976	1,976
Decrease in development locations	(6,905)	(10,158)	(10,158)
Cascadura discovery	15,805	20,428	20,428
Total undiscounted change	10,545	12,246	12,246
Total undiscounted change (%)	19	15	15

Summary of Pricing and Inflation Rate Assumptions

The following table sets forth benchmark reference pricing and inflation rates reflected in the Reserves Report.

Forecast Year	Brent Spot  Crude Oil  ($/bbl)^(1)	NYMEX Henry Hub Natural Gas ($/MMBtu)^(1)	Conway Condensate ($/bbl)^(1)	Inflation Rates  (% per year)^(2)
2021	50.75	2.75	43.20	0.0
2022	55.00	2.80	46.35	1.0
2023	58.50	2.85	49.05	2.0
2024	61.79	2.90	52.01	2.0
2025	62.95	2.95	53.06	2.0
2026	64.13	3.01	54.12	2.0
2027	65.33	3.07	55.20	2.0
2028	66.56	3.13	56.30	2.0
2029	67.81	3.19	57.43	2.0
2030	69.17	3.25	58.58	2.0
Thereafter	+2.0% / year	+2.0% / year	+2.0% / year	2.0

Notes:
(1)	This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. Product sales prices will reflect these reference prices with further adjustments for marketing arrangements, quality differentials and transportation to point of sale.
(2)	Inflation rates for forecasting pricing and costs.

Estimated Company Capital Program Efficiency

	Proved Reserves	Proved plus Probable Reserves
Estimated capital expenditures ($000's)^(1)	18,349	18,349
Change in FDC required to develop reserves ($000's)	10,545	12,246
Estimated F&D costs($000's)^(2)	28,894	30,595
Gross reserve additions (Mboe)^(2),^(^3)	22,902	43,395
Estimated F&D costs per boe ($/boe)^(2)	1.26	0.71
Estimated 2020 operating netback ($/boe)^(1),(4)	14.29	14.29
Estimated 2020 recycle ratio^(2)	11.3x	20.3x

Notes:
(1)	Financial information is based on the Company's preliminary 2020 unaudited financial statements and is therefore subject to audit. See "Advisories: Unaudited Financial Information".
(2)	See "Advisories: Reserves Advisory" and "Advisories: Oil and Gas Metrics".
(3)	Gross reserves are the Company's working interest share of the remaining reserves before deduction of any royalties.
(4)	See "Non-GAAP Measures".

Advisories

Forward-Looking Statements

Certain information provided in this news release may constitute forward-looking statements and information (collectively, "forward-looking statements") within the meaning of applicable securities laws. Such forward-looking statements include, without limitation, forecasts, estimates, expectations and objectives for future operations that are subject to assumptions, risks and uncertainties, many of which are beyond the control of the Company. Forward-looking statements are statements that are not historical facts and are generally, but not always, identified by the words "expects", "plans", "anticipates", "believes", "intends", "estimates", "projects", "potential" and similar expressions, or are events or conditions that "will", "would", "may", "could" or "should" occur or be achieved.

Forward-looking statements in this news release may include, but is not limited to, statements relating to estimated crude oil and natural gas reserves and the net present values of future net revenue therefrom, the forecasted future production, commodity prices, inflation rates and all future costs used by GLJ in their evaluation, the potential undertaking, timing, locations and costs of future well testing, well drilling, well tie-in and seismic operations, the expected timing of initial production from exploration wells and the expected execution of a drilling rig contract, including drilling rig mobilization timing and costs. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. Certain of these risks are set out in more detail in the Company's 2019 Annual Information Form dated March 25, 2020 which has been filed on SEDAR and can be accessed at www.sedar.com. The forward-looking statements contained in this news release are made as of the date hereof, and except as may be required by applicable securities laws, the Company assumes no obligation to update publicly or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise.

In addition, statements relating to reserves are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. The recovery and reserve estimates of Touchstone's reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Consequently, actual results may differ materially from those anticipated in the forward-looking statements.

Reserves Advisory

The disclosure in this news release summarizes certain information contained in the Reserves Report but represents only a portion of the disclosure required under NI 51-101. Full disclosure with respect to the Company's reserves as at December 31, 2020 will be contained in the Company's Annual Information Form for the year ended December 31, 2020 which will be filed on SEDAR on or before March 31, 2021.

The recovery and reserve estimates of crude oil and natural gas reserves provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil and natural gas reserves may eventually prove to be greater than or less than the estimates provided herein. This news release summarizes the crude oil and natural gas reserves of the Company and the net present values of future net revenue for such reserves using forecast prices and costs as at December 31, 2020 prior to provision for interest and finance costs, general and administration expenses, the impact of any financial derivatives or liabilities associated with the abandonment and reclamation of certain facilities and wells. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material.

"Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing, or if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Proved Developed Non-Producing Reserves" are those reserves that either have not been on production or have previously been on production but are shut-in, and the date of resumption of production is unknown.

"Proved Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.

"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

"Possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

In the Reserves Report, GLJ forecasted reserve volumes and future cash flows based upon current and historical well performance through to the economic production limit of individual wells. Notwithstanding established precedence and contractual options for the continuation and renewal of the Company's existing licence, sub-licence and marketing agreements, in many cases the forecasted economic limit of individual wells is beyond the current term of the relevant agreements. There is no certainty as to any renewal of the Company's existing exploration, production, and marketing arrangements.

Oil and Gas Measures

Where applicable, natural gas has been converted to barrels of oil equivalent based on six thousand cubic feet to one barrel of oil. The barrel of oil equivalent rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.

Oil and Gas Metrics

This news release contains several oil and gas metrics that are commonly used in the oil and gas industry such as reserves additions, finding and development costs, and recycle ratio. These metrics have been prepared by Management and do not have standardized meanings or standardized methods of calculation, and therefore such measures may not be comparable to similar measures presented by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company, and future performance may not compare to the performance in prior periods, and therefore such metrics should not be unduly relied upon. The Company uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment purposes.

Net reserve additions are calculated as the change in reserves from the beginning to the end of the applicable period excluding period production. Management uses this measure to determine the relative change of its reserves base over a period of time.

F&D costs represent the costs of exploration and development incurred. Specifically, F&D is calculated as the sum of exploration and development capital expenditures incurred in the period and the change in future development costs required to develop those reserves. The Company's annual audit of its December 31, 2020 consolidated financial statements is not complete. Accordingly, unaudited capital expenditure amounts used in the calculation of F&D costs are Management's estimates and are subject to change. F&D costs per barrel is determined by dividing current period net reserve additions to the corresponding period's F&D cost. Readers are cautioned that the aggregate of capital expenditures incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect total F&D costs related to net reserves additions for that year. Management uses F&D costs as a measure of its ability to execute its capital program, the success in doing so, and of the Company's asset quality.

Recycle ratio is a measure used by Management to evaluate the effectiveness of its capital reinvestment program and is calculated by dividing the annual F&D costs per barrel to operating netback per barrel prior to realized gains or losses on commodity derivative contracts in the corresponding period (see "Non-GAAP Measures"). The Company's annual audit of its December 31, 2020 consolidated financial statements is not complete. Accordingly, unaudited operating netbacks used in calculations of recycle ratios are Management's estimates and are subject to change. The recycle ratio compares netbacks from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement of reserves are of equivalent quality as the produced reserves.

Unaudited Financial Information

Certain annual 2020 financial information disclosed herein including capital expenditures and operating netback are based on unaudited estimated results and are subject to the same limitations as discussed in Forward-Looking Statements set out above. These estimated results are subject to change upon completion of the Company's audited financial statements for the year ended December 31, 2020, and changes could be material. Touchstone anticipates filing its audited consolidated financial statements and related management's discussion and analysis for the year ended December 31, 2020 on SEDAR on March 26, 2021.

Non-GAAP Measures

The Company uses operating netback as a key performance indicator of field results. Operating netback is presented on a total and per barrel basis and is calculated by deducting royalties and operating expenses from petroleum sales. Operating netback is presented herein prior to realized gains or losses on commodity derivative contracts. Operating netback does not have a standardized meaning under Generally Accepted Accounting Principles and therefore may not be comparable with the calculation of similar measures by other companies. The Company considers operating netback to be a key measure as it demonstrates Touchstone's profitability relative to current commodity prices. This measurement assists Management and investors in evaluating operating results on a historical basis.

Abbreviations
bbl(s)	barrel(s)
bbls/d	barrels per day
Mbbl	thousand barrels
Mcf	thousand cubic feet
MMcf	million cubic feet
Bcf	billion cubic feet
MMBtu	million British Thermal Units
boe	barrels of oil equivalent
Mboe	thousand barrels of oil equivalent
API	American Petroleum Institute gravity

Touchstone Exploration Inc.

Touchstone Exploration Inc. is a Calgary, Alberta based company engaged in the business of acquiring interests in petroleum and natural gas rights and the exploration, development, production and sale of petroleum and natural gas. Touchstone is currently active in onshore properties located in the Republic of Trinidad and Tobago. The Company's common shares are traded on the Toronto Stock Exchange and the AIM market of the London Stock Exchange under the symbol "TXP".

SOURCE Touchstone Exploration Inc.

about Touchstone, please visit our website at www.touchstoneexploration.com or contact: Mr. Paul Baay, President and Chief Executive Officer; or Mr. James Shipka, Chief Operating Officer. Telephone: [phone]

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